After drilling a hole through a subsurface formation and determining that the formation can yield an economically sufficient amount of oil or gas, a crew completes the well. During drilling, completion, and production maintenance, personnel routinely insert and/or extract devices such as tubing, tubes, pipes, rods, hollow cylinders, casing, conduit, collars, and duct into the well. For example, a service crew may use a workover or service rig to extract a string of tubing and sucker rods from a well that has been producing petroleum. The crew may inspect the extracted tubing and evaluate whether one or more sections of that tubing should be replaced due physical wear, thinning of the tubing wall, chemical attack, pitting, or another defect. The crew typically replaces sections that exhibit an unacceptable level of wear and note other sections that are beginning to show wear and may need replacement at a subsequent service call.
As an alternative to manually inspecting tubing, the service crew may deploy an instrument to evaluate the tubing as the tubing is extracted from the well and/or inserted into the well. The instrument typically remains stationary at the wellhead, and the workover rig moves the tubing through the instrument's measurement zone. The instrument typically measures pitting and wall thickness and can identify cracks in the tubing wall. Radiation, field strength (electrical, electromagnetic, or magnetic), and/or pressure differential may interrogate the tubing to evaluate these wear parameters. The instrument typically samples a raw analog signal and outputs a sampled or digital version of that analog signal.
In other words, the instrument typically stimulates a section of the tubing using a field, radiation, or pressure and detects the tubing's interaction with or response to the stimulus. An element, such as a transducer, converts the response into an analog electrical signal. For example, the instrument may create a magnetic field into which the tubing is disposed, and the transducer may detect changes or perturbations in the field resulting from the presence of the tubing and any anomalies of that tubing.
While the instrument can provide important and detailed information about the damage or wear to the tubing, this data can be difficult to analyze for single sections of tubing and even more difficult for an entire stand of tubing withdrawn from a well. While the instrument typically outputs data at or near a constant rate, the speed at which the tubing is withdrawn from the well is variable. At least a portion of the variability in speed is necessitated by the fact that the tubing sections must be separated from one another. During separation, the workover rig comes to a complete stop and the tubing section is separated form a collar that holds two pieces of tubing together. Once the particular tubing section is separated and stored, the workover rig can continue withdrawing the next section of tubing from the well. Variability in speed can also be caused by the fact that there is no predetermined speed at which oilfield service operators are instructed to withdraw the tubing from the well. Furthermore, tight speed control and monitoring has not historically been seen as an important factor in tubing removal.
Because of the speed variations the data output by the instrument and displayed on a display panel is typically inconsistent. For example, if a long delay occurs in uncoupling one tubing section from another, the display of the data from the instrument could cover an area greater than the viewable area of the display screen. This may lead the operator to make evaluations of the tubing section based on partial data, because the operator may not be able to determine when the tubing section began and ended in the data displayed. On the other hand, if the operators are able to withdraw and separate the tubing quickly, the display could potentially display more than one tubing section. In this situation, the operator could make decisions for one tubing section based on data that was actually from a different section of tubing.
Furthermore, once all of the tubing has been removed from the well and the data is charted, the data may include information showing particular problems within the well. However, to date, the analysis data does not include the capability of displaying the data with a depth component so that the operators can determine exactly where in the well the problem is occurring and focus their repair analysis on that particular section.
To address these representative deficiencies in the art, what is needed is an improved capability for evaluating tubing analysis. For example, a need exists for communicably tying the information output from an encoder or other positional sensor on the workover rig with the computer processing the tubing analysis data. Furthermore, a need exists for apparatus and method for reliably detecting collars on the tubing sections and displaying the position of the collars in relation to the other tubing analysis data being processed. Another need exists for a method of providing positional or depth data with the tubing analysis data displayed for oilfield service operators to assist in detecting major problems or data anomalies from the well and tubing analysis. A capability addressing one or more of these needs would provide more accurate, precise, repeatable, efficient, or profitable tubing evaluations.